As is commonly known, electricity generation and demand must be kept in balance at to maintain system reliability and power quality. When the electric demand drops, it is necessary to throttle back some generators and/or take certain generators off line. When the demand increases, additional generator capacity must be brought on-line or the output of on-line generators increased.
Power system frequency stability is desired and is a function of a balance between generation and consumption. If there is too much generation, residual power is transformed into generator shaft kinetic energy and the line frequency increases. If there is inadequate generation relative to the amount of power consumed, generators take shaft kinetic energy and convert it to electric power, reducing the system frequency. Power system operators try to maintain a constant frequency by matching generation to load.
In a typical power system certain generators are considered frequency-responsive or frequency support generators and other generators are not able to provide frequency stabilization. Examples of the latter may include generators coupled to nuclear generating stations, base load coal plants, and peaking units. Nuclear units and base load coal plants respond too slowly to an event that creates an under frequency or an over frequency condition. Thus these units are usually exempt from participating frequency control.
Generating units reserved for duty during peak power demands are normally brought to full-load generating capacity immediately upon start-up and thus are already in service during capacity shortages. These units may or may not have control algorithms associated with frequency response. However, since they are operated at maximum load they generally cannot respond to under-frequency events. Also, when peaking units are brought on line, the power system must have sufficient online capacity to respond to over-frequency events. Thus peaking units seldom participate in frequency control.
Synchronous generators respond to grid frequency changes according to either an inertial response or a governor response (i.e., a droop response).
Synchronous generators driven by a steam or gas turbine have an inherent inertial response as a consequence of the physical characteristics of the rotating turbine mass. This inertial response is initiated by an incident such as a change in the electrical torque caused by grid frequency changes. This inertial response is fast, inherent, uncontrolled and transient. Duration of a typical inertial response is about 5 to 20 seconds. After the inertial response ends, the generator output returns to its pre-incident condition because of the energy extracted during the response period.
Synchronous generators are also controlled to a new operating condition according to a governor response during which the amount of mechanical power supplied to the generator is controlled (increased or decreased) by altering the fuel flow to a gas turbine or the steam flow to a steam turbine. The fuel flow or steam flow remains at this new level until the next governor response to another incident.
There are conventionally two governor response modes, the droop mode and the isochronous mode, to match generation to load demand and thereby maintain a grid frequency of 60.00 Hz in North America. If neither of these control schemes are sufficient to maintain that balance, generating units can be manually brought on-line or taken off-line as needed.
Generating units that follow load and are therefore designated as frequency-responsive generators, (these units typically include, for example, combined cycle generators and non-base-load steam generators) are controlled according to a speed droop setting. A typical droop setting in the United States is 4% or 5%. Droop-mode generators are controlled to decrease their power output if the frequency goes above a predetermined dead band, which is typically either +0.0166 or +0.036 Hz from a nominal frequency (60 Hz in North America). These generators are also controlled to increase their power output (if they have sufficient generation headroom) when the frequency drops below a dead band, e.g., 0.0166 or 0.036 Hz below the nominal frequency of 60 Hz or 50 Hz.
All droop mode turbine controllers on the power system work in concert to share load demand changes among all operating turbines-generators. The load demand change is shared in proportion to a ratio of the base load rating of each generator to the overall grid generating capacity. A typical droop characteristic for a generator is 5%. If the frequency changes by 5% or more, there will be a 100% change in generator output.
In practice, most frequency variations are considerably less than this 5% value. A large frequency excursion is generally considered on the order of 0.25% or 0.15 Hz for a 60 Hz grid frequency. Any frequency deviation larger than this is considered an emergency condition that initiates an under-frequency load shedding incident.
If a unit operates according to a 5% droop, in response to a 5% frequency change the unit responds with a 100% change in output (based on the nameplate rating of the generator). A 1% frequency change corresponds to a 20% change in output power; a 2% frequency change corresponds to 40% change in output power, etc.
For example if a unit rated at 100 MW is operating at an output power of 50 MW and the frequency suddenly drops to 59.4 Hz (a 1% reduction), the turbine controller detects this change and the generator is expected to increase its output by 20 MW (20% of its rated output) to 70 MW. The output is controlled to increase in a very short period of time. Time requirements vary but a typical requirement is one minute or less.
If the frequency rises to 61.2 Hz (a 2% increase), the unit is expected to reduce its output by 40 MW (40% of 100 MW) to 10 MW or to its minimum load, whichever is greater.
As those skilled in the art are aware, there are a few nuances in the application of these rules. For example, instead of an absolute threshold value for increasing or decreasing generator output, a dead-band frequency range can be implemented. If the frequency change is within this dead band range the generator output does not change. System operators may utilize a relatively wide or a relatively narrow dead-band width or dead-band range. Further, the frequency deviation may be measured from an edge of a dead band or from a center of the dead-band.
The actual system frequency threshold or dead band range (and the other variables set forth in the immediately preceding paragraph) that cause the frequency responsive reserves to be activated are determined by the independent system operator.
This threshold may be greater than 59.5 Hz, since there are some older operating turbines that have under-speed trip points at 3570 rpm, which corresponds to 59.5 Hz. Thus the 59.5 Hz value is significantly below the dead band imposed by system operators. In North America the dead band threshold is typically either 59.983 Hz or 58.964 Hz. When the line frequency drops below this value the frequency-responsive generators increase their output as explained above.
The formula for determining the increase or decrease of a generator's output (A MW) is:ΔMW=(fo−freq)×Pnom/(fo×pu droop)
Where, ΔMW is the desired change in MW output,                fo is the nominal system or line frequency (60 Hz in North America),        freq is the actual frequency measured,        Pnom is the nominal output of the generator, and        pu droop is the percent droop rating divided by 100.        
For the second example set forth above,
fo=60
freq=61.2
Pnom=100
pu droop=0.05 and therefore
and therefore,ΔMW=(60−61.2)×100/(60×0.05)ΔMW=−40
Calculations such as those set forth above that estimate a desired change in system output may be inaccurate because real turbines and generators have operating limits that are not explicitly considered in the governing equation. For example, a unit that is already generating its maximum or minimum load (i.e., its nameplate capacity) cannot respond, respectively, to an under-frequency or an over-frequency event.
Often the operating limits of a turbine or generator are dictated by pollution emissions, which can vary from site to site and even from season to season.
For example, if the system load or system demand is 10,000 MW and an incident occurs that causes a 1% frequency drop (thus requiring a 20% increase in system output), there may not be an output change of 2000 MW. Although there may be 12000 MW on-line and therefore the output can theoretically increase to 12000 MW, a substantial portion of the 12000 MW may not be able to fully respond to the demand increase either because turbines are already operating at their capacity limit or because the turbines are not equipped for frequency response operation. Thus the actual system response may be much smaller than as calculated according to the formula above.
Very large under-frequency deviations usually invoke an automatic under-frequency load shedding event to prevent generators from tripping off line. Generators typically trip when subjected to large frequency excursions for an extended period (which, in some cases, may be more than only a few seconds). These load shedding events are typically mass customer disconnections. In some cases entire towns may be disconnected.
Over-frequency incidents are usually much easier to solve by simply reducing system generation.
When electric demand drops significantly, for example during the overnight hours, the droop and isochronous control schemes may not be sufficient to balance the generation and load. Instead, it may be necessary to throttle back some generators and/or take certain generators off line. But it is desired, if not required in some circumstances, that certain generators must be kept operating at a minimum level, e.g., base load generators especially including base load generators coupled to nuclear generating stations. Thus the power system operator may “curtail” certain generators (i.e., reducing generation supplied to the grid below 100% of the power available (where power available is determined by present wind conditions), even to 0% power output) or taking the generating unit off-line during such periods.
Combustion generators (whether using oil, diesel or biofuel as the fuel source) can be throttled back to a certain degree. Peak generating units are turned off when the peak demand, usually from about 5 to 9 PM on weekdays, is over. Cycling generating units are also turned down or off as demand drops in the late evening. Base-loaded generating units, usually the largest, steam turbine units on the grid, are only infrequently turned down and then only to their minimum required generation level.
If more energy reductions are needed to balance generation and load, most transmission system operators curtail wind turbine generators (and wind turbine parks comprising several wind turbine generators proximately situated in a geographic region) to less than 100% of available output. In a curtailed operating mode the wind turbine generator or the wind turbine park is operating at less than the total power available from current wind conditions. Thus such curtailments occur even when the wind is blowing and additional energy can be extracted from the wind (i.e., additional generation is available). Transmission system operators prefer to curtail the wind turbine generators (WTGs) during these off-peak periods in lieu of curtailing a base load unit or taking it off line. The ability of a transmission system operator to curtail WTGs makes these units more challenging to operate efficiently and profitably.
There are two forms of WTGs: fixed speed WTGs and variable speed WTGs.
In a fixed-speed WTG wind-driven blades drive a blade rotor that in turn operates through a gear box (i.e., a transmission) to turn a gearbox output shaft at a fixed speed. The gearbox output shaft is connected to an induction (asynchronous) generator for generating real power.
In the induction generator the rotor and its associated conductors rotate faster than the rotating flux applied to the stator from the grid (i.e., higher than the synchronous field frequency). The difference in these two values is referred to as “slip.” At this higher speed, the direction of the induced rotor current is reversed, in turn reversing the counter EMF (electromotive force) generated in the rotor windings, and by generator action (induction) causing current (and real power) to be generated in and flow from the stator windings. The frequency of the voltage generated in the stator is the same as the frequency of the voltage applied to the stator to develop the stator excitation.
The fixed-speed wind turbine is simple, reliable, low-cost and proven. But its disadvantages include uncontrollable reactive power consumption (as required to generate the stator rotating flux), mechanical stresses, limited control of power quality and relatively inefficient operation. In fact, wind speed fluctuations result in mechanical torque fluctuations that can result in fluctuations in the electrical power on the grid.
Variable speed WTG operation can be achieved only by decoupling the electrical grid frequency and the mechanical rotor frequency. The rotational blade speed of a variable speed WTG can be controlled to continuously adapt to the wind speed and maximize the power generated by the wind turbine. Since an electric generator is usually coupled to a variable speed WTG rotor through a fixed-ratio gear transmission, the electrical power produced by the generator has a variable frequency.
An electronic power converter is interposed between the generator output and a power system or grid to which the WTG supplies power. Generally, the power converter imparts characteristics to the generated electricity that match the electricity flowing on the grid, including controllable active power flow, voltage magnitude and frequency. Thus the converter converts the variable electrical frequency voltage output from the generator stator to the grid frequency and voltage. The power converter also electrically and mechanically decouples the grid from the WTG.
Although variable-speed WTGs are advantageous from the perspective of increased energy conversion and reduced mechanical stresses, the electrical generation system is more complicated than that of a constant speed wind turbine due primarily to the need for a power converter.
Both fixed speed and variable speed WTGs are designed to operate in parallel with a synchronous generator, both supplying power to the grid. The WTG's synchronize to the grid frequency to produce a constant frequency electrical output.
FIG. 1 illustrates a prior art wind turbine generator park 1 comprising variable speed wind turbine generators 2, 3.
The WTGs 2, 3 generate electrical power that is supplied to a utility grid or power system 37. Preferably, the WTGs 2, 3 are variable speed wind turbines, i.e., the rotational speed of their respective generator rotors is variable depending on wind conditions.
Each WTG 2, 3 comprises turbine blades 4, 5 attached to a rotor shaft 6, 7 for transmitting the torque of the wind-driven blades 4, 5 to a gearbox 8, 9. An output shaft of the gearbox 8, 9 drives an AC generator 17, 19 for transforming the mechanical power provided by rotation of the rotor shaft 6, 7 to electrical power. The gearbox 8, 9 provides a transmission ratio that allows the gearbox output shaft to turn at a different speed than the rotor shaft 6, 7. Preferably the gearbox output shaft turns at a speed that optimizes the electricity generated by the AC generators 17, 19.
The AC generator 17, 19 can comprise either a synchronous generator or an asynchronous (induction) generator and further each comprises power electronics components. Generally, in a synchronous generator, a generator rotor rotates at the same rotational frequency as the rotating magnetic field produced by a generator stator (or with an integer relationship to the frequency of the rotating magnetic field, where that integer relationship depends on the number of rotor pole pairs).
In contrast thereto, in an asynchronous generator (induction generator) the rotational frequency of the stator's magnetic field (conventionally 60 Hz when the stator magnetizing current is supplied from the electrical grid) is independent from the rotational frequency of the rotor. The difference in rotational frequency of the rotor and the stator is numerically described by a slip value.
If the generators 17, 19 of FIG. 1 comprise synchronous generators, the frequency of the output power therefrom depends on wind velocity. But that output frequency must be converted to the frequency of the power system 37 to which the generators 17, 19 supply electricity.
The frequency conversion process is accomplished by action of power electronics frequency converters 21, 23. Each frequency converter converts the frequency of the electrical power delivered by generators 17, 19 into an electrical power having a fixed frequency corresponding to the frequency of the power system 37. Each frequency converter 21, 23 comprise a respective generator-side converter (rectifier) 25, 27 for converting the AC current produced by the generator 17, 19 into a DC current. A network-side converter (an inverter) 29, 31 converts the DC current back to an AC current at the frequency of the power system 37. The AC output of the network-side converter 29, 31 is supplied to the power system 37 from the node 35 through a transformer 33.